Fractures in a hydrocarbon producing formation are sometimes beneficial to enhanced hydrocarbon production. Often, a formation is intentionally fractured by high pressure fracturing fluids to increase the conductivity of a formation to allow fluids to more readily travel through the formation to a producing well bore. It is known that the cooler the temperature of fracturing fluids, the easier it is to break down a formation.
Thomas Perkins and Jay Gonzalez published a SPE paper (SPE 10080) in October 1981, entitled Changes in Earth Stresses Around a Wellbore Caused by Radially Symmetrical Pressure and Temperature Gradients, wherein they cited water flooding as an example of where a large volume of cooler liquid was injected into a higher temperature in situ reservoir. It was noted that cooling can have a large effect on lateral earth stresses. And in some conditions, vertical hydraulic fracturing pressures can be significantly reduced using the cooler fracturing fluids.
In other circumstances, it is undesirable to have excessive fracturing of formations, such as when drilling a well bore utilizing circulating fluids. Circulating fluids are also commonly referred to as “mud” due to their composition and appearance. Circulating fluids serve to (1) lubricate and cool drilling bits drilling a well bore in a formation; (2) flush cuttings from a well bore up to the surface of a well; and (3) provide a pressure head which counteracts and helps control the influx of fluids from formations surrounding a well bore.
Typically, this mud is mixed in circulating tanks adjacent to the drilling rig drilling a well bore. The constituents comprising the mud are adjusted as needed to meet a variety of drilling concerns. The mud is typically not heated. An exception occurs at cold weather drilling sites where mud must not be allowed to freeze. For economic reasons, only enough heat is added to prevent the mud from freezing.
A significant problem in drilling wells is maintaining a sufficient mud weight to maintain well control. Concurrently, the weight of the mud must be sufficiently low so that the pressure head applied by the mud does not appreciably create or enhance fractures in the formation being drilled. Such fractures can lead to large losses of circulating fluids into the formation. This problem is commonly referred to as a “lost returns” problem as the circulating fluids fail to return to the surface of a well. These “lost returns” problems are particularly acute in (1) deep water wells; (2) areas with high geothermal formation temperatures; (3) steam flood operations; and (4) drilling through naturally fractured formations.
The lost circulation fluids can result in much higher drilling costs. First, the circulating fluids often include expensive components such as synthetic oil, weighting agents, emulsifiers, surfactants, and polymers which must be replenished. Second, the cost of drilling is time related. For example, it can cost as much as $400,000 a day to use a drill ship to drill a deep water well. “Lost returns” problems increase the time necessary to drill a well because of well control issues.
Prior techniques to mitigate “lost returns” problems have included reducing the weight of the mud column. For example, dual gradient drilling may be used to decrease the pressure head on the formation being drilled.
U.S. Pat. No. 6,450,262 discusses methods for mitigating lost circulating problems including the use of dual gradient drilling.
There is a need for an improved method and system for controlling lost circulation returns when drilling well bores into subterranean formations. This is particularly true for highly fractured formations, formations at great depths, and when drilling deep water wells. The present invention addresses this need by providing a method and system for mitigating circulation return losses.